Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
 
ý     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended December 31, 2015September 30, 2016
 
o        TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from          to          
 
Commission File Number 001-32942
 
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
 
Nevada 41-1781991
(State or other jurisdiction of incorporation or organization) (IRS Employer Identification No.)
 
2500 CityWest Blvd.,1155 Dairy Ashford Road, Suite 1300,425, Houston, Texas 7704277079
(Address of principal executive offices and zip code)
 
(713) 935-0122
(Registrant’s telephone number, including area code)
 
Not Applicable
(Former name, former address and former fiscal year if changed since last report)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ý No: o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes: ý No: o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 
Large accelerated filer o
 
Accelerated filer x
   
Non-accelerated filer o
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: o No: ý
 
The number of shares outstanding of the registrant’s common stock, par value $0.001, as of February 2,November 4, 2016, was 32,881,445.33,045,515.



EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
 
TABLE OF CONTENTS
 
  Page
   
   
   
 
 
 
 
 
   
   
   
   
   
   
   
   
   
   
   
   
 



1


PART I — FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Balance Sheets
(Unaudited) 


December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Assets 
  
 
  
Current assets 
  
 
  
Cash and cash equivalents$16,325,013
 $20,118,757
$28,236,711
 $34,077,060
Receivables2,557,731
 3,122,473
2,518,470
 2,638,188
Deferred tax asset
 82,414

 105,321
Derivative assets, net1,323,749
 

 14,132
Prepaid expenses and other current assets396,018
 369,404
273,114
 251,749
Total current assets20,602,511
 23,693,048
31,028,295
 37,086,450
Oil and natural gas property and equipment, net (full-cost method of accounting)49,049,250
 45,186,886
61,451,021
 59,970,463
Other property and equipment, net38,279
 276,756
50,585
 28,649
Total property and equipment49,087,529
 45,463,642
61,501,606
 59,999,112
Other assets225,355
 726,037
348,014
 365,489
Total assets$69,915,395
 $69,882,727
$92,877,915
 $97,451,051
Liabilities and Stockholders’ Equity 
  
 
  
Current liabilities 
  
 
  
Accounts payable$4,902,135
 $8,173,878
$2,509,041
 $5,809,107
Preferred shares called for redemption7,932,975
 
Accrued liabilities and other1,262,275
 855,373
839,313
 2,097,951
Derivative liabilities, net
 109,974
Deferred income taxes367,661
 
State and federal income taxes payable342,930
 190,032
97,078
 621,850
Total current liabilities6,875,001
 9,329,257
11,378,407
 8,528,908
Long term liabilities 
  
 
  
Deferred income taxes10,244,897
 11,242,551
12,444,045
 11,840,693
Asset retirement obligations692,976
 715,767
772,175
 760,300
Deferred rent
 18,575
Total liabilities17,812,874
 21,306,150
24,594,627
 21,129,901
Commitments and contingencies (Note 16)

 

Commitments and contingencies (Note 15)

 

Stockholders’ equity 
  
 
  
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at December 31, 2015 and June 30, 2015 with a liquidation preference of $7,932,975 ($25.00 per share)317
 317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,881,445 shares and 32,845,205 as of December 31, 2015 and June 30, 2015, respectively32,881
 32,845
Preferred stock, par value $0.001; 5,000,000 shares authorized:8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at September 30, 2016 and June 30, 2016; with a liquidation preference of $7,932,975; called for redemption at September 30, 2016 (Note 8)
 317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,045,515 shares and 32,907,863 as of September 30, 2016 and June 30, 2016, respectively33,045
 32,907
Additional paid-in capital40,063,167
 36,847,289
40,222,825
 47,171,563
Retained earnings12,006,156
 11,696,126
28,027,418
 29,116,363
Total stockholders’ equity52,102,521
 48,576,577
68,283,288
 76,321,150
Total liabilities and stockholders’ equity$69,915,395
 $69,882,727
$92,877,915
 $97,451,051
 

See accompanying notes to consolidated condensed financial statements.

2


Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Operations
(Unaudited)
 
Three Months Ended 
 December 31,
 Six Months Ended 
 December 31,
Three Months Ended   September 30,
2015 2014 2015 20142016 2015
Revenues 
  
  
  
 
  
Delhi field$6,558,215
 $7,644,831
 $13,854,601
 $11,513,433
Artificial lift technology64,712
 63,236
 147,732
 179,092
Other properties
 
 
 20,369
Crude oil$7,593,855
 $7,325,813
Natural gas liquids89
 1,050
Natural gas(4) 704
Artificial lift technology services
 51,839
Total revenues6,622,927
 7,708,067
 14,002,333
 11,712,894
7,593,940
 7,379,406
Operating costs 
  
  
  
   
Production costs - Delhi field2,226,141
 2,817,866
 4,784,028
 2,817,866
Production costs - artificial lift technology53,731
 191,553
 113,245
 388,913
Production costs - other properties
 9,390
 1,046
 97,412
Production costs2,344,641
 2,608,579
Cost of artificial lift technology services
 9,868
Depreciation, depletion and amortization1,471,571
 917,757
 2,689,844
 1,287,107
1,273,439
 1,218,273
Accretion of discount on asset retirement obligations11,517
 8,137
 22,860
 12,773
13,224
 11,343
General and administrative expenses *2,057,521
 1,606,501
 3,742,366
 3,111,094
1,235,043
 1,684,845
Restructuring charges**1,257,433
 (5,431) 1,257,433
 (5,431)
Total operating costs7,077,914
 5,545,773
 12,610,822
 7,709,734
4,866,347
 5,532,908
Income (loss) from operations(454,987) 2,162,294
 1,391,511
 4,003,160
Income from operations2,727,593
 1,846,498
Other 
  
  
  
 
  
Gain on settled derivative instruments, net1,298,201
 
 2,164,628
 
Gain on unsettled derivative instruments, net361,761
 
 1,433,723
 
Gain on realized derivative instruments, net90
 866,427
Gain (loss) on unrealized derivative instruments, net(14,132) 1,071,962
Delhi field insurance recovery related to pre-reversion event
 
 1,074,957
 

 1,074,957
Interest income5,853
 7,662
 11,665
 20,425
Interest (expense)(18,666) (12,159) (37,126) (30,619)
Interest and other income12,745
 5,812
Interest expense(20,345) (18,460)
Income before income taxes1,192,162
 2,157,797
 6,039,358
 3,992,966
2,705,951
 4,847,196
Income tax provision368,889
 917,879
 2,123,858
 1,624,038
889,176
 1,754,969
Net income attributable to the Company823,273
 1,239,918
 3,915,500
 2,368,928
1,816,775
 3,092,227
Dividends on preferred stock168,576
 168,576
 337,151
 337,151
250,990
 168,575
Deemed dividend on preferred shares called for redemption$1,002,440
 $
Net income available to common stockholders$654,697
 $1,071,342
 $3,578,349
 $2,031,777
$563,345
 $2,923,652
Earnings per common share          
Basic$0.02
 $0.03
 $0.11
 $0.06
$0.02
 $0.09
Diluted$0.02
 $0.03
 $0.11
 $0.06
$0.02
 $0.09
Weighted average number of common shares 
  
  
  
 
  
Basic32,741,166
 32,825,631
 32,729,705
 32,754,016
32,957,010
 32,718,244
Diluted32,802,440
 32,947,280
 32,789,461
 32,884,754
33,007,599
 32,774,176
 
* General and administrative expenses for the three months ended December 31,September 30, 2016 and 2015 and 2014 included non-cash stock-based compensation expense of $212,724$311,688 and $245,020, respectively. For the corresponding six month periods, non-cash stock-based compensation expense was $430,839 and $488,357,$218,115, respectively.

** Restructuring charges include $569,228 of non-cash impairment charges and $59,339 of non-cash stock-based compensation for the three months and six months ended December 31, 2015.

3

Table of Contents

Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statements of Cash Flows
(Unaudited)
 
Six Months Ended 
 December 31,
Three Months Ended   September 30,
2015 20142016 2015
Cash flows from operating activities 
  
 
  
Net income attributable to the Company$3,915,500
 $2,368,928
$1,816,775
 $3,092,227
Adjustments to reconcile net income to net cash provided by operating activities: 
  
 
  
Depreciation, depletion and amortization2,714,162
 1,311,425
1,287,523
 1,230,432
Impairments included in restructuring charge569,228
 
Stock-based compensation430,839
 488,357
311,688
 218,115
Stock-based compensation included in restructuring charge59,339
 
Accretion of discount on asset retirement obligations22,860
 12,773
13,224
 11,343
Settlements of asset retirement obligations
 (220,522)(15,899) 
Deferred income taxes(547,579) 656,589
708,673
 (12,568)
Deferred rent
 (8,574)
(Gain) on derivative instruments, net(3,598,351) 
(Gain) loss on derivative instruments, net14,042
 (1,938,389)
Write-off of deferred loan costs50,414
 

 50,414
Changes in operating assets and liabilities: 
  
 
  
Receivables from oil and natural gas sales1,176,758
 (1,454,866)
Receivables other(9,367) (12,492)
Receivables119,808
 757,617
Prepaid expenses and other current assets(119,515) 69,697
(21,365) 47,815
Accounts payable and accrued expenses(310,054) 1,384,201
(2,235,240) (1,563,847)
Income taxes payable152,898
 45,392
(524,772) 343,704
Net cash provided by operating activities4,507,132
 4,640,908
1,474,457
 2,236,863
Cash flows from investing activities 
  
 
  
Derivative settlements received1,561,979
 
Proceeds from asset sales
 389,166
Derivative settlement payments (paid) received(318,708) 551,772
Capital expenditures for oil and natural gas properties(8,650,217) (1,136)(4,818,816) (6,571,757)
Capital expenditures for other property and equipment
 (311,075)(26,347) 
Other assets(161,345) (84,341)
 (23,802)
Net cash used in investing activities(7,249,583) (7,386)(5,163,871) (6,043,787)
Cash flows from financing activities 
  
 
  
Cash dividends to preferred stockholders(337,151) (337,151)(168,575) (168,575)
Cash dividends to common stockholders(3,268,319) (6,565,350)(1,652,290) (1,629,703)
Acquisition of treasury stock(1,354,743) (58,660)
Common share repurchases, including shares surrendered for tax withholding(330,070) (1,175,920)
Tax benefits related to stock-based compensation3,910,163
 921,581

 2,980,832
Other(1,243) (11,292)
 (1,276)
Net cash used in financing activities(1,051,293) (6,050,872)
Net cash (used in) provided by financing activities(2,150,935) 5,358
Net decrease in cash and cash equivalents(3,793,744) (1,417,350)(5,840,349) (3,801,566)
Cash and cash equivalents, beginning of period20,118,757
 23,940,514
34,077,060
 20,118,757
Cash and cash equivalents, end of period$16,325,013
 $22,523,164
$28,236,711
 $16,317,191

Supplemental disclosures of cash flow information:Six Months Ended 
 December 31,
Three Months Ended   September 30,
2015 20142016 2015
Income taxes paid$440,000
 $100,000
$787,366
 $
Louisiana carryback income tax refund and related interest received$1,556,999
 $

 1,556,999
Non-cash transactions: 
  
 
  
Change in accounts payable used to acquire property and equipment(2,442,183) 1,410,420
(2,030,485) (4,072,935)
Accrued redemption of called preferred shares7,932,975
 
Accrued preferred dividends through redemption date82,415
 
Deferred loan costs charged to oil and gas property costs108,472
 

 108,472
Oil and natural gas property costs incurred through recognition of asset retirement obligations
 562,482
Settlement of accrued treasury stock purchases(170,283) 

 (170,283)
Royalty rights acquired through non-monetary exchange of patent and trademark assets108,512
 
 See accompanying notes to consolidated condensed financial statements.

4


Evolution Petroleum Corporation and Subsidiaries
Consolidated Condensed Statement of Changes in Stockholders' Equity
For the SixThree Months Ended December 31, 2015September 30, 2016
(Unaudited)

Preferred Common Stock        Preferred Common Stock        
Additional
Paid-in
Capital
 Retained
Earnings
 Treasury
Stock
 Total
Stockholders'
Equity
Additional
Paid-in
Capital
 Retained
Earnings
 Treasury
Stock
 Total
Stockholders'
Equity
Shares Par Value Shares Par Value Shares Par Value Shares Par Value 
Balance at June 30, 2015317,319
 $317
 32,845,205
 $32,845
 $36,847,289
 $11,696,126
 $
 $48,576,577
Balance at June 30, 2016317,319
 $317
 32,907,863
 $32,907
 $47,171,563
 $29,116,363
 $
 $76,321,150
Issuance of restricted common stock
 
 272,098
 272
 (239) 
 
 33

 
 195,799
 196
 (196) 
 
 
Forfeitures of restricted stock
 
 (31,467) (31) 31
 
 
 
Acquisition of treasury stock
 
 (204,391) 
 
 
 (1,184,460) (1,184,460)
Common share repurchases, including shares surrendered for tax withholding
 
 (58,147) 
 
 
 (330,070) (330,070)
Retirements of treasury stock
 
 
 (205) (1,184,255) 
 1,184,460
 

 
 
 (58) (330,012) 
 330,070
 
Stock-based compensation
 
 
 
 490,178
 
 
 490,178

 
 
 
 311,688
 
 
 311,688
Tax benefits related to stock-based compensation
 
 
 
 3,910,163
 
 
 3,910,163
Accrued redemption of preferred shares
 (317) 
 
 (6,930,218) (1,002,440) 
 (7,932,975)
Accrued dividends on preferred stock through redemption date
 
 
 
 
 (82,415) 
 (82,415)
Net income attributable to the Company
 
 
 
 
 3,915,500
 
 3,915,500

 
 
 
 
 1,816,775
 
 1,816,775
Common stock cash dividends
 
 
 
 
 (3,268,319) 
 (3,268,319)
 
 
 
 
 (1,652,290) 
 (1,652,290)
Preferred stock cash dividends
 
 
 
 
 (337,151) 
 (337,151)
 
 
 
 
 (168,575) 
 (168,575)
Balance at December 31, 2015317,319
 $317
 32,881,445
 $32,881
 $40,063,167
 $12,006,156
 $
 $52,102,521
Balance at September 30, 2016317,319
 $
 33,045,515
 $33,045
 $40,222,825
 $28,027,418
 $
 $68,283,288


 See accompanying notes to consolidated condensed financial statements.


5

Table of Contents
Evolution Petroleum Corporation And Consolidated Subsidiaries
 Notes to Unaudited Consolidated Condensed Financial Statements





Note 1 Organization and Basis of Preparation
 
Nature of Operations.  Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology.
 
Interim Financial Statements.  The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the appropriate rules and regulations of the Securities and Exchange Commission (“SEC”).  Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to such rules and regulations.  All adjustments (consisting of normal recurring accruals) which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented have been included.  The interim financial information and notes hereto should be read in conjunction with the Company’s 20152016 Annual Report on Form 10-K for the fiscal year ended June 30, 2015,2016, as filed with the SEC. The results of operations for interim periods are not necessarily indicative of results to be expected for a full fiscal year.
 
Principles of Consolidation and Reporting.  Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our artificial lift technology operations at December 31, 2015, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells which used our artificial lift technology, together with service revenues derived from the use of the Company’s technology on third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services.
 
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

New Accounting Pronouncement.Pronouncements.
In NovemberAugust 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any.
On February 25, 2016, the FASB issued ASU 2016-02 , Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions.  This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning

6

Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.

New Accounting Pronouncements Adopted.

The Company early adopted ASU No. 2015-17, “BalanceBalance Sheet Classification of Deferred Taxes” as partTaxes, to be applied prospectively effective for the three months ended September 30, 2016. This amended guidance simplifies the statement of their simplification initiatives.financial position presentation and reduces complexity in accounting for deferred income tax assets and liabilities. The update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. As a result current deferred tax assets of $105,321 have been netted together with noncurrent deferred income tax liabilities on the September 30, 2016 consolidated condensed balance sheet. The update isprior period presented has not been retrospectively adjusted.

The Company early adopted ASU 2016-09, Compensation - Stock Compensation:  Improvements to Employee Share-Based Payment Accounting, effective for public company annual reportingthe three months ended September 30, 2016. This amended guidance simplifies and improves several aspects of the accounting for employee share-based payment transactions. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. For vestings which occurred in the first quarter ended September 30, 2016, a related tax deficiency of $215,594 was recognized in income tax expense. The Company also elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flow. Accordingly, such statements for pre-adoption periods beginning after December 15, 2016, and maywill continue to present excess tax benefits in the financing section. The amended guidance permits entities to make an accounting policy election related to how forfeitures will impact the recognition of compensation cost for stock-based compensation: to continue to estimate the total number of awards for which the requisite service period will not be adopted prospectivelyrendered as currently required or, retrospectively withto be applied on a modified retrospective basis, to account for forfeitures as they occur. Upon early adoption, is permitted. At present, the Company does not believe that adoptionelected to change its accounting policy to account for forfeitures as they occur. Except for income tax expense mentioned above, none of the other provisions in this update will haveamended guidance had a material impact on our results of operations,condensed consolidated financial position or cash flows.statements.

Note 2 — Restructuring Charge

Separation of GARP Artificial Lift Technology Operations

During the quarter ended December 31, 2015, we conducted a strategic review of our GARP® artificial lift technology operations and consummated a plan to separate and transfer these operations to a new entity controlled by the inventor of the technology, our Senior Vice President of Operations, and certain former employees of the Company. We invested $108,750 in common and preferred stock of the new entity, Well Lift Inc. ("WLI"). We own 17.5% of WLI and our former employees own the balance of the common stock. Our preferred stock is convertible at our option into common stock which would result in our ownership of 42.5% of WLI, based on the current capital structure of WLI. The company has no contractual exposure to losses of WLI, nor does it have any obligation or agreement to provide additional funding or support to WLI if it is needed. In connection with this transaction, three employees of the Company were terminated. We accrued a restructuring charge based on agreements with the employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for release from liabilities and other provisions including agreements not to compete. Our estimate of accounting charges related to the personnel restructuring as of December 31, 2015 is as follows:


6

Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Type of Cost December 31,
2015
Salary expense $530,387
Payroll taxes and benefits expense 98,479
Stock compensation expense 59,339
Personnel restructuring charge $688,205

Other Restructuring Impairments

Also in connection with the separation of GARP®, the Company and WLI entered into an agreement under which we transferred our technology assets, including our patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP® technology. We reduced the carrying value of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512. This estimate was based on the recent financial results from our artificial lift technology operations and the current depressed state of the oil and gas industry and the potential upside cases were assigned relatively low probabilities for accounting purposes. This resulted in an impairment charge of $469,395. In addition, we transferred certain inventory and minor fixed assets to WLI which had no further use in our operations and were deemed to have negligible market or salvage value. This resulted in impairments of $92,901 to equipment inventory and $6,932 to fixed assets, respectively. These impairments total $569,228 and are included in restructuring charges for the three months ended December 31, 2015.

Note 32 — Receivables

As of December 31, 2015September 30, 2016 and June 30, 20152016, our receivables consisted of the following:

December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Receivables from oil and gas sales$1,945,397
 $3,122,155
$2,514,990
 $2,637,593
Receivable from settled derivatives602,649
 
90
 
Other9,685
 318
3,390
 595
Total receivables$2,557,731
 $3,122,473
$2,518,470
 $2,638,188

Note 43 — Prepaid Expenses and Other Current Assets

As of December 31, 2015September 30, 2016 and June 30, 20152016, our prepaid expenses and other current assets consisted of the following:

December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Prepaid insurance$133,927
 $178,994
$111,927
 $168,681
Equipment inventory (a)
 81,538
Retainers and deposits26,978
 26,978
30,568
 30,568
Prepaid federal and state income taxes204,694
 22,542
82,091
 
Other prepaid expenses30,419
 59,352
48,528
 52,500
Prepaid expenses and other current assets$396,018
 $369,404
$273,114
 $251,749

(a) As discussed in Note 2, our equipment inventory was determined to have no future value in use for our operations and was charged to restructuring costs as part of the separation of our GARP® artificial lift technology operations.


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 Notes to Unaudited Consolidated Condensed Financial Statements


Note 54 Property and Equipment
 
As of December 31, 2015September 30, 2016 and June 30, 20152016, our oil and natural gas properties and other property and equipment consisted of the following:
December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Oil and natural gas properties 
  
 
  
Property costs subject to amortization$64,024,239
 $57,718,653
$80,196,684
 $77,408,353
Less: Accumulated depreciation, depletion, and amortization(14,974,989) (12,531,767)(18,745,663) (17,437,890)
Unproved properties not subject to amortization
 

 
Oil and natural gas properties, net$49,049,250
 $45,186,886
$61,451,021
 $59,970,463
Other property and equipment 
  
 
  
Other equipment, at cost$337,245
 $607,674
Furniture, fixtures and office equipment, at cost$255,099
 $228,752
Artificial lift technology equipment, at cost7,000
 7,000
Less: Accumulated depreciation(298,966) (330,918)(211,514) (207,103)
Other equipment, net$38,279
 $276,756
Other property and equipment, net$50,585
 $28,649
 
During the sixthree months ended December 31, 2015September 30, 2016, the Company incurred capital expenditures of $6.3$2.8 million for the Delhi field, including approximately $4.4$2.4 million for the NGL plant project which is currently in progress. We have incurred approximately $9.4$23.9 million on a cumulative basis for the NGL plant out of a total authorized commitment of $24.6 million.

During the three months ended December 31, 2015, we recorded a charge of $210,392 to expense the remaining capitalized costs of certain artificial lift equipment installed in the wells of a third-party customer. We continue to own this equipment and contract rights, but do not expect to realize any significant future value from this investment at current prices.
Note 65 Other Assets

As of December 31, 2015September 30, 2016 and June 30, 20152016, other assets consisted of the following:
 December 31,
2015
 June 30,
2015
Royalty rights$108,512
 $
Investment in Well Lift Inc., at cost108,750
 
Trademarks
 44,803
Patent costs
 538,276
Less: Accumulated amortization of patent costs
 (47,063)
Deferred loan costs179,468
 337,078
Less: Accumulated amortization of deferred loan costs(171,375) (147,057)
Other assets, net$225,355
 $726,037
During the quarter ended September 30, 2015, our plan to obtain a new expanded secured credit facility was postponed due to market conditions. As a result, the Company determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $108,472 of deferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. As discussed in Note 15, the Company is in discussions with the Lender to extend the maturity, renew the current unsecured Credit Agreement or seek a similar source of bank financing. As of December 31, 2015, there were $8,093 of unamortized deferred loan costs related to our existing unsecured credit facility.
See Note 2 for discussion of transactions associated with the separation of our GARP® artificial lift technology operations.
 September 30,
2016
 June 30,
2016
Royalty rights$108,512
 $108,512
Less: Accumulated amortization of royalty rights(10,173) (6,782)
Investment in Well Lift Inc., at cost108,750
 108,750
Deferred loan costs168,972
 168,972
Less: Accumulated amortization of deferred loan costs(28,047) (13,963)
Other assets, net$348,014
 $365,489
The companyCompany accounts for its investment in WLIWell Lift Inc. using the cost method under which any return of capital reduces cost and any dividends paid are recorded as income. This investment is considered a level 3 fair value measurement and itsInvestment value will be evaluated for impairment periodically andat least quarterly or when management identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.

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 Notes to Unaudited Consolidated Condensed Financial Statements



Note 76 Accrued Liabilities and Other
 
As of December 31, 2015September 30, 2016 and June 30, 20152016, our other current liabilities consisted of the following:
December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Accrued incentive and other compensation$366,967
 $578,910
$161,408
 $999,172
Asset retirement obligations due within one year102,874
 57,223
145,209
 201,896
Accrued royalties, including suspended accounts45,999
 75,164
43,679
 49,580
Accrued franchise taxes63,792
 94,885
36,900
 62,834
Accrued restructuring charge628,866
 
Accrued restructuring costs316,625
 419,488
Payables for settled derivatives
 318,708
Dividends declared on preferred shares82,415
 
Other accrued liabilities53,777
 49,191
53,077
 46,273
Accrued liabilities and other$1,262,275
 $855,373
$839,313
 $2,097,951
 
Accrued Restructuring Costs

On December 31, 2015 we terminated three employees of the Company in connection with the separation of our artificial lift technology operations. We recorded a personnel restructuring charge of $688,205, consisting of $59,339 in stock-based compensation from accelerated vesting of equity awards and $628,866 of accrued salary and benefit continuation expenses. The separation agreements included releases from liabilities and other provisions including agreements not to compete. Our current estimate of remaining restructuring obligations as of September 30, 2016 is as follows:
Type of Cost December 31,
2015
 Payments September 30,
2016
Salary expense $530,387
 $(265,193) $265,194
Payroll taxes and benefits expense 98,479
 (47,048) 51,431
Accrued liability for restructuring costs $628,866
 $(312,241) $316,625

Note 87 Asset Retirement Obligations
 
Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and
remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a
reconciliation of the beginning and ending asset retirement obligations for the sixthree months ended December 31, 2015,September 30, 2016 and for the year ended June 30, 2015:2016:
December 31,
2015
 June 30,
2015
September 30,
2016
 June 30,
2016
Asset retirement obligations — beginning of period$772,990
 $352,215
$962,196
 $772,990
Liabilities incurred (a)
 564,019

 28,505
Liabilities settled
 (137,604)(10,219) 
Liabilities sold(a)
 (52,526)(47,817) 
Accretion of discount22,860
 34,866
13,224
 49,054
Revision of previous estimates
 12,020

 111,647
Asset retirement obligations — end of period$795,850
 $772,990
$917,384
 $962,196
Less current portion in accrued liabilities(b)(102,874) (57,223)(145,209) (201,896)
Long-term portion of asset retirement obligations692,976
 715,767
$772,175
 $760,300
 
(a) Liabilities incurred during fiscal 2015 relateWe conveyed our interest in a well to the previous operator in exchange for the assumption of our shareasset retirement obligation.

(b) We expect to retire our three remaining operated wells within the next twelve months. After such operations are completed, our asset retirement obligations will consist entirely of the the estimated abandonment costs of the wells and facilitiesour working interest obligations in the Delhi field subsequent to the reversion of our working interest.field.

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Notes to Unaudited Consolidated Condensed Financial Statements


Note 98 — Stockholders’ Equity

 Common Stock Dividends and Buyback Program
 
Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. During the sixthree months ended December 31, 2015,September 30, 2016, the Company declared twoone quarterly dividendsdividend on its common stock and paid $3,268,319$1,652,290 to its common stockholders.

On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. CommencingSince commencing in June 2015, 265,762 shares have been repurchased at an average price of $6.05 per share (totaling $1,609,008) including 202,390. There has been no shares purchased duringrepurchased in the six months ended December 31, 2015, at an average price of $5.80 (totaling $1,173,899).open market since mid-December 2015. Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase programit may be suspended or discontinued at any time. Such

During the three months ended September 30, 2016, the Company acquired 58,147 shares are initially recorded asof treasury stock thenat an average cost of $5.68 per share (totaling $330,070) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the quarter. The treasury shares were subsequently canceled.

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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notestreasury stock at an average cost of $5.75 per share (totaling $999,731) under its share repurchase program and also acquired 1,073 shares of treasury stock at an average cost of $5.50 per share (totaling $5,906) from holders of newly vested stock-based awards to Unaudited Consolidated Condensed Financial Statementsfund the recipients' payroll taxes paid in the quarter. All treasury shares were subsequently canceled.



 Series A Cumulative Perpetual Preferred Stock Called for Redemption

At December 31, 2015, there wereOn September 30, 2016, the Company declared the preferred dividend for the month of October 2016 and elected to redeem all 317,319 outstanding shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding.  Stock. The redemption will occur on November 14, 2016 at the issue's $25.00 per share liquidation value plus all accumulated and unpaid distributions from October 31, 2016 (the last dividend payment date before the redemption date) through the redemption date, for an aggregate redemption price of approximately $25.082639 per share:
Consideration to preferred shareholders upon redemption at liquidation preference$7,932,975
Accrued and unpaid dividends (1)$82,415
Deemed dividend (2)$1,002,440
(1) Includes the monthly dividend for October 2016 declared by the Company.
(2) Represents the difference between the redemption consideration and the historical carrying value of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share.

The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the holders thereof. Effective July 1, 2014, we can redeem this preferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt.  Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $337,151$168,575 to holders of our Series A Preferred Stock during each of the six month periodsthree months ended December 31, 2015September 30, 2016 and 2014.2015.

Expected Tax Treatment of Dividends

For the fiscal year ended June 30, 2015, 100% of cash2016, we expect all preferred and common dividends on preferred stock wereto be treated for tax purposes as qualified dividend income. Approximately 86% of cash dividends on common shares were treated as a return of capitalincome to stockholders and the remainder of 14% were treated as qualified dividend income.recipients. Based on our current projections for the fiscal year ending June 30, 2016,2017, we expect all common and remaining preferred and common dividends for such period will be treated as qualified dividend income.

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Notes to Unaudited Consolidated Condensed Financial Statements


Note 109 — Stock-Based Incentive Plan
 
Under the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration on October 24, 2017 and 257,1882017. As of September 30, 2016, 64,236 shares remain available for grant as of December 31, 2015.under the Plan.
 
Stock Options

No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. The following summary presents information regarding outstanding Stock Options as of December 31, 2015,September 30, 2016, and the changes during the period:
 Number of Stock
Options
and Incentive
Warrants
 Weighted Average
Exercise Price
 Aggregate
Intrinsic Value
(1)
 Weighted
Average
Remaining
Contractual
Term (in
years)
Stock Options outstanding at July 1, 201591,061
 $2.50
  
  
Expired(5,830) 4.02
    
   Stock Options outstanding at December 31, 201585,231
 2.40
 $205,305
 0.9
   Vested and exercisable at December 31, 201585,231
 $2.40
 $205,305
 0.9
 Number of Stock
Options
 Weighted Average
Exercise Price
 Aggregate
Intrinsic Value
(1)
 Weighted
Average
Remaining
Contractual
Term (in
years)
Stock Options outstanding at July 1, 201635,231
 $2.19
  
  
Exercised
 
  
  
Expired
 
    
   Stock Options outstanding at September 30, 201635,231
 2.19
 $144,095
 0.9
   Vested and exercisable at September 30, 201635,231
 $2.19
 $144,095
 0.9
(1) Based upon the difference between the market price of our common stock on the last trading date of the period ($4.816.28 as of December 31, 2015)September 30, 2016) and the Stock Option exercise price of in-the-money Stock Options.

Restricted Stock and Contingent Restricted Stock

Prior to August 28, 2014, all Restricted Stock grants contained a four-year vesting period based solely on service. Restricted Stock which vests based solely on service is valued at the fair market value on the date of grant and amortized over the service period.

In August 2014, and in December 2015 and September 2016, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were

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Notes to Unaudited Consolidated Condensed Financial Statements


issued on the date of grant, whereas the Contingent Restricted Stock are reserved from the Plan, but will be issued only upon the attainment of specified performance-based or market-based vesting provisions.

Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four- yearfour-year term. As of December 31, 2015,September 30, 2016, certain performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense wouldwill be recorded at that time and amortization would continue over the remaining expected vesting period.

Market-based awards granted in 2014 and 2015 entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. Market-based awards granted in 2016 entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of an index consisting of designated peer companies during defined measurement periods. The fair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. During the sixthree months ended DecemberSeptember 30, 2015,2016, we granted market-based

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awards with grant date fair values ranging from $3.42 to $5.62 per share, all with an expected vesting period of 2.83 years, based on the various quartiles of comparative market performance. During the fiscal year ended June 30, 2016, we granted market-based awards with grant date fair values ranging from $2.93 to $5.07 per share, all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance.  During the fiscal year ended June 30, 2015, we had granted market-based awards with grant date fair values ranging from $4.26 to $8.40 per share and with expected vesting periods of 3.30 years to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

Unvested Restricted Stock awards at December 31, 2015September 30, 2016 consisted of the following:
Award Type Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Service-based awards 214,269
 7.50
 252,167
 6.64
Performance-based awards 120,386
 7.92
 54,475
 5.67
Market-based awards 93,254
 5.50
 147,729
 5.48
Unvested at December 31, 2015 427,909
 $7.18
Unvested at September 30, 2016 454,371
 $6.15
The following table sets forth the Restricted Stock transactions for the sixthree months ended December 31, 2015:September 30, 2016:
Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)Number of
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at September 30, 2016 Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2015262,227
 $9.37
   
Unvested at July 1, 2016406,848
 $6.74
   
Service-based shares granted142,594
 6.09
   54,473
 5.67
   
Performance-based shares granted64,752
 6.09
   54,475
 5.67
   
Market-based shares granted64,752
 4.58
   54,475
 5.44
   
Vested(74,949) 8.62
   (115,900) 7.44
   
Forfeited(31,467) 9.39
   
 
   
Unvested at December 31, 2015427,909
 $7.18
 $2,298,812
 2.9
Unvested at September 30, 2016454,371
 $6.15
 $2,152,183
 2.8
(1) Excludes $559,121 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

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 Notes to Unaudited Consolidated Condensed Financial Statements


Unvested Contingent Restricted Stock awards at December 31, 2015September 30, 2016 consisted of the following:
Award Type Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
Performance-based awards 60,196
 $7.92
 39,403
 $7.02
Market-based awards 46,630
 3.34
 73,867
 3.37
Unvested at December 31, 2015 106,826
 $5.92
Unvested at September 30, 2016 113,270
 $4.64
The following table sets forth Contingent Restricted Stock transactions for the sixthree months ended December 31, 2015:September 30, 2016:
 Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at December 31, 2015 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 201556,286
 $8.20
    
Performance-based awards granted32,376
 6.09
    
Market-based awards granted32,376
 2.93
    
Forfeited(14,212) 8.54
    
Unvested at December 31, 2015106,826
 $5.92
 $128,898
 3.2
 Number of
Contingent
Restricted
Shares
 Weighted
Average
Grant-Date
Fair Value
 Unamortized Compensation Expense at September 30, 2016 (1) Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 201691,172
 $5.21
    
Performance-based awards granted27,237
 5.67
    
Market-based awards granted27,237
 3.42
    
Vested(32,376) 6.09
    
Unvested at September 30, 2016113,270
 $4.64
 $186,703
 2.7
(1) Excludes $476,761$276,702 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.
Stock-based compensation expense related to Restricted Stock and contingentContingent Restricted Stock grants for the three months ended December 31,September 30, 2016 and 2015 was $311,688 and 2014 was $272,063 and $245,020,$218,115, respectively. For the six months ended December 31, 2015 and 2014, this expense was $490,178 and $488,357, respectively.
Note 1110 Derivatives
In early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecasted productionproduction. The Company's objectives for this program were to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The Company uses both fixed price swap agreements and costless collars the Company uses to manage risk are designedits exposure to establish floor and ceiling prices on anticipated futurecrude oil production.price risk. While the use of these derivative instruments limitsare intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. We also use swap agreements in which we exchange our exposure to floating crude spot prices for a fixed price for our production over a period of time.
The Company does not intend to enter into derivative instruments for speculative or trading purposes.
The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedging ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in income.  Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815.  Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings.
These derivative instruments can result in both fair value asset and liability positions held with that counterparty, whicheach counterparty. These positions are all offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value derivative instruments where the Company is in a net asset position with its counterparty as of December 31, 2015 totaled $1,323,749. Refer to Note 12—Fair Value Measurement for derivative asset and derivative liability balances before offsetting.
The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As

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such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments.
The Company held no crude oil derivative instruments as of September 30, 2016 and has not subsequently acquired any crude oil derivative positions.

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For the sixthree months ended December 31,September 30, 2016, the Company recorded in the consolidated statement of operations a loss on derivative instruments of $14,042 consisting of a realized gain of $90 on settled derivatives and an unrealized net loss of $14,132 on unsettled derivatives. For the three months ended September 30, 2015, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $3,598,351$1,938,389 consisting of a realized gain of $2,164,628$866,427 on settled derivatives and an unrealized net gainloss of $1,433,723$1,071,962 on unsettledunrealized derivatives.
The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of December 31, 2015.
Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl.
Months of January 2016 through March 2016 Fixed Price Swap 1,100 $51.65
Subsequent to December 31, 2015, the Company realized a gain of $677,703 on derivative contracts which expired at the end of January 2016. We had previously recorded an unrealized gain of $483,839 on these contracts as of December 31, 2015.
Note 1211 Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
The three levels are defined as follows:
Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.
Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.
Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of December 31, 2015. All items included in the tables below are Level 2 inputs within the fair value hierarchy:
  December 31, 2015
Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets $1,323,749
 $
 $1,323,749
Current derivative liabilities 
 
 
Total $1,323,749
 $
 $1,323,749
The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparty's credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.
Note 1312 Income Taxes
 
We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions.
 

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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the sixthree months ended December 31, 2015.September 30, 2016.  We believe we have appropriate support for the income tax positions taken and to be taken on our tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of manyvarious factors including past experience and interpretations of tax law applied to the facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations for the years endingended June 30, 20122013 through June 30, 20142015 for federal tax purposes and for the years ended June 30, 2011 through June 30, 20142015 for state tax purposes. To the extent we utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.

We recognized income tax expense of $889,176 and $1,754,969 for the three months ended September 30, 2016 and 2015, respectively, with corresponding effective rates of 33% and 36%. Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the stateState of Louisiana, with smallerand differences related to stock basedpercentage depletion in excess of basis, stock-based compensation and other permanent differences. Statutory percentage depletion gives rise to a permanent difference in our tax rates when utilized for state or federal income tax purposes.

In late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We also received $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resulted from the exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we recognized this benefit as an increase in additional paid-in capital for financial reporting purposes. This carryback utilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes. The remaining balance of this net loss carryforward in Louisiana was utilized in the tax return for the year ended June 30, 2015.
We recognized income tax expense of $2,123,858 and $1,624,038 for the six months ended December 31, 2015 and 2014, respectively, with corresponding effective rates of 35% and 41%. The lower effective tax rate for the three months ended September 30, 2016 resulted primarily from percentage depletion in 2015 resulted from a lesser amountexcess of taxablebasis, partially offset by state income intaxes and the statetax effects of Louisiana.stock-based compensation.

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Evolution Petroleum Corporation And Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Note 1413 Net Income Per Share
 
The following table sets forth the computation of basic and diluted income per share:
Three Months Ended December 31, Six Months Ended December 31,Three Months Ended September 30,
2015 2014 2015 20142016 2015
Numerator 
  
  
  
 
  
Net income available to common shareholders$654,697
 $1,071,342
 $3,578,349
 $2,031,777
$563,345
 $2,923,652
Denominator 
  
  
  
 
  
Weighted average number of common shares — Basic32,741,166
 32,825,631
 32,729,705
 32,754,016
32,957,010
 32,718,244
Effect of dilutive securities: 
  
  
  
 
  
Contingent restricted stock grants9,795
 6,432
 9,322
 1,785
28,845
 6,788
Stock options51,479
 115,217
 50,434
 128,953
21,744
 49,144
Weighted average number of common shares and dilutive potential common shares used in diluted EPS32,802,440
 32,947,280
 32,789,461
 32,884,754
33,007,599
 32,774,176
          
Net income per common share — Basic$0.02
 $0.03
 $0.11
 $0.06
$0.02
 $0.09
Net income per common share — Diluted$0.02
 $0.03
 $0.11
 $0.06
$0.02
 $0.09
 
Outstanding potentially dilutive securities as of December 31,September 30, 2016 were as follows:
Outstanding Potentially Dilutive Securities Weighted
Average
Exercise Price
 At September 30, 2016
Contingent Restricted Stock grants (a) $
 113,270
Stock Options 2.19
 35,231
  $0.52
 148,501
Outstanding potentially dilutive securities as of September 30, 2015 were as follows:
Outstanding Potential Dilutive Securities Weighted
Average
Exercise Price
 At December 31, 2015
Contingent Restricted Stock grants (a) $
 46,630
Stock Options 2.40
 85,231
  $1.55
 131,861

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Evolution Petroleum Corporation And Consolidated Subsidiaries
Notes to Unaudited Consolidated Condensed Financial Statements


Outstanding potentially dilutive securities as of December 31, 2014 were as follows:
Outstanding Potential Dilutive Securities Weighted
Average
Exercise Price
 At December 31, 2014
Outstanding Potentially Dilutive Securities Weighted
Average
Exercise Price
 At September 30, 2015
Contingent Restricted Stock grants (a) $
 17,961
 $
 17,961
Stock Options 2.25
 141,061
 2.40
 85,231
 $2.00
 159,022
 $1.98
 103,192
(a) Contingent Restricted Stock grants for which vesting is not considered probable for accounting purposes are excluded from potentially dilutive securities outstanding.
Note 1514Unsecured RevolvingSenior Secured Credit Agreement

On February 29, 2012, Evolution Petroleum CorporationApril 11, 2016, the Company entered into a Credit Agreement (the "Credit Agreement") with Texas Capital Bank, N.A. (the "Lender"). The Credit Agreement provides the Company with a revolvingnew three-year, senior secured reserve-based credit facility (the “facility”("Facility") in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000.  A portion of$50 million. The Facility replaces the Company's previous unsecured credit facility notwhich expired in excess of $1,000,000 is available for the issuance of letters of credit.
The facility is unsecured and has a term of four years, expiring on February 29,April 2016. The Company's subsidiaries guarantee the Company's obligationsinitial borrowing base under the facility. The proceedsFacility was set at $10,000,000. As of any loansSeptember 30, 2016, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the facilityFacility.
Proceeds from the Facility may be used by the Company for the acquisition and development of oil and gas properties as defined in the facility, the issuance ofand for letters of credit and for working capital andother general corporate purposes.
Semi-annually, the borrowing base and a monthly reduction amount are re-determined from reserve reports.  Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender’s credit approval process, and are also limited to 25% Availability of the value of our oil and gas properties, as defined in the Credit Agreement.
At the Company's option, borrowings under the facilityFacility is subject to semi-annual borrowing base redeterminations.
The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000, and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at a rate ofthe Company’s option, at either (i) an Adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender’s Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender’s prime rateLibor plus 2.75% or the sum of 0.50%Prime Rate, as defined, plus the Federal Funds Rate. A maximum of three LIBOR based loans can be outstanding at any time.  Allowed loan interest periods are one, two, three and six months.  LIBOR interest is payable at the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term.  Base Rate interest is payable monthly.  Letters of credit bear fees of 3.5% per annum rate applied to the principal amount and are due when transacted.  The maximum term of letters of credit is one year.
A commitment fee of 0.50% per annum accrues on unutilized availability and is payable quarterly.  The Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as $50,000 in loan costs incurred upon closing.
The Credit Agreement also contains financial covenants including a requirement that the Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1.  The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other than permitted indebtedness, and it restricts certain asset sales.  Payments of dividends for the Series A Preferred are only restricted by the EBITDA to interest coverage ratio, wherein such dividends are a 1X deduction from EBITDA (as opposed to a 3:1 requirement if dividends were treated as interest expense)1.00%. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the Lender may declare any amounts outstanding under the Credit Agreement to be immediately due and payable.Facility

As of December 31, 2015 and 2014, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000, and we are in compliance with all the covenants of the Credit Agreement. During early 2014 the Lender waived the provisions of the Credit Agreement pertaining to the past payments of cash dividends on our common stock, and the Credit Agreement was amended to permit the payment of cash dividends on common stock in the future if no borrowings are outstanding at the time of such payment.
In connection with this agreement, the Company incurred $179,468 of debt issuance costs that have been capitalized in Other Assets and are being amortized on a straight-line basis over the term of the agreement. The unamortized balance in debt

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Evolution Petroleum Corporation And Consolidated Subsidiaries
 Notes to Unaudited Consolidated Condensed Financial Statements


contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $40 million, all as defined under the Facility.
In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Credit AgreementFacility was $8,093$140,925 as of December 31, 2015. The Company is in discussions with the Lender to extend the maturity, renew the current unsecured Credit Agreement or seek a similar source of bank financing.September 30, 2016.
Note 1615 — Commitments and Contingencies
 
We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.

On December 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We also alleged that Denbury’s gross negligence caused certain environmental damage to the unit.  Specifically, we allege that Denbury failed to properly conduct CO2 injection activities.We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims, including the assertion that we owe Denbury additional revenue interests pursuant to the 2006 agreements and that our transfers of the reversionary interests from our wholly owned subsidiary to our parent corporation and subsequently to another wholly-owned subsidiary were not timely noticed to Denbury. The Company disagrees with, and is vigorously defending against, Denbury's counterclaims. In March 2015, we amended and expanded our claims in this matter. This matter is set for trial in April 2016.

On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed certain claims against NGS Sub Corp. The plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and discovery is in process. We will continue to vigorously defend all claims by plaintiffs and consider the likelihood of a material loss to the Company in this matter to be remote.

Lease Commitments.  We have a non-cancelable operating lease for office space that expires on JulyMay 31, 2016.2019. Future minimum lease commitments as of December 31, 2015September 30, 2016 under this operating lease are as follows: 
Twelve months ended December 31, 
2016$92,756
Twelve months ended September 30, 
2017$73,073
2018$73,073
2019$66,984
 
Rent expense for the three months ended December 31,September 30, 2016 and 2015 was $34,856 and 2014 was $45,857 and $43,776,$45,043, respectively. For the six months ended December 31, 2015 and 2014, rent expense was $90,900 and $87,551.

Capital Expenditures. See Note 54 for discussion of capital projects in progress and expected remaining capital commitments.

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Note 16 — Subsequent Event
On November 7, 2016, the Company announced that its Board of Directors increased the quarterly cash dividend to common shareholders to $0.065 per share. The dividend will payable on December 30, 2016 to shareholders of record as of the close of business on December 15, 2016.


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended June 30, 20152016 (the “Form 10-K”), along with Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Form 10-K.  Any terms used but not defined herein have the same meaning given to them in the Form 10-K.
 
This Form 10-Q and the information referenced herein contain forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in our 20152016 Annual Report on Form 10-K for the year ended June 30, 20152016 as filed with the Securities and Exchange Commission. Furthermore, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to Evolution Petroleum Corporation are expressly qualified in their entirety by this cautionary statement.
 
We use the terms, “EPM,” “Company,” “we,” “us” and “our” to refer to Evolution Petroleum Corporation and its wholly owned subsidiaries.

Executive Overview
 
General

We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our stockholders and customers utilizing conventional and proprietary technology. We are focused on increasing underlying asset values on a per share basis. In doing so, we depend on a conservative capital structure, allowing us to maintain control of our assets for the benefit of our stockholders, and a substantial stock ownership by our directors, officers and staff. By policy, every employee and director maintains a beneficial ownership in our common stock.

Our strategy is to grow the value of our Delhi asset to maximize the value realized by our stockholders.

We are currently funding our fiscal 20162017 capital program from working capital and net cash flows from our properties.
 
Highlights for our SecondFirst Quarter of Fiscal 20162017 and Operations Update

"Current quarter" refers to the three months ended December 31, 2015,September 30, 2016, the Company's 2nd1st quarter of fiscal 2017.

"Prior quarter" refers to the three months ended June 30, 2016, the Company's 4th quarter of fiscal 2016.

"PriorYear-ago quarter" refers to the three months ended September 30, 2015, the Company's 1st quarter of fiscal 2016.

"Year-ago quarter" refers to the three months ended December 31, 2014, the Company's 2nd quarter of fiscal 2015.
 
Highlights

NetWe reported net income of $1.8 million in the current quarter. Our net income to common shareholders was $0.7$0.6 million, or $0.02 per diluted common share.share, which includes a nonrecurring, noncash deemed dividend of $1.0 million related to the redemption of our preferred stock and $0.3 million of final dividends on the preferred stock.

Gross production in the Delhi field was 5.8% higher than the prior quarter, increasing to 7,371 barrels of oil equivalent per day (“BOEPD”) from 6,964 BOEPD, primarily from conformance and production enhancement operations. This production does not yet include expected volumes from the new Delhi NGL plant, which is scheduled for completion and start-up in the next fiscal quarter.
Delhi
Our net production increased to 1,8011,935 BOEPD, after a small 0.2% (.002) adjustment to our net revenue interest from the June 2016 litigation settlement. Our average realized price per equivalent barrel was $42.66, down slightly from the $42.87 average price in the prior quarter.

We announced the redemption of all of our 8.5% Series A Cumulative Preferred Stock. Annual preferred dividend savings will amount to $674,302 per year.

We ended the quarter with $19.6 million of working capital, substantially all of which was cash, after reduction for the $7.9 million commitment to retire our preferred stock. We remain debt free.
Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2016.
Delhi Field - Enhanced Oil Recovery Project

Gross production at Delhi in the first quarter of fiscal 2017 averaged 7,371 barrels of oil per day (“BOPD”("BOPD"), an increase of 15% from the year-ago quarter, and a 6%5.8% increase overfrom the prior quarter. GrossThe year-over-year increase in production volumes was primarily the result of conformance operations and other production enhancements which improved production rates. Our interests in the Delhi field increased to 6,810 BOPD from 6,423 BOPD in the prior quarter.
consist of a 23.9% working interest (with associated 19.0% net revenue interest) and separate royalty interests of 7.2%. This yields a total net revenue interest of 26.2%.

Average realized oil price was $39.59 per barrel, down from $46.70Field operating expenses were $13.14 per barrel in the current quarter compared to $11.72 in the prior quarter, resultingprimarily as a result of higher purchased CO2 costs. In the quarter ended September 30, 2016, our net share of lease operating expenses was approximately $2.3 million, of which $1.1 million is related to CO2 purchases and transportation expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in Delhi revenuesthe field per thousand cubic feet (“Mcf”) plus sales taxes of $6.6 million8% plus transportation costs of $0.20 per Mcf. CO2 costs increased 26% from the prior quarter as a result of higher purchased field volumes which averaged 73.7 MMcf per day gross compared to $7.3 million58.7 MMcf per day in the prior quarter. Realized hedge gains added $1.3Total CO2 injection volumes increased during the summer, with a corresponding increase in purchased volumes. Our cost of purchased CO2 is tied directly to realized oil prices in the field, so our cost per Mcf was largely unchanged from quarter to quarter. On a total BOE basis, CO2 costs increased 19% from $5.09 per BOE in the prior quarter to $6.06 per BOE.

Based on recent discussions with the operator, the fabrication, construction and installation of the NGL plant is essentially complete, with initial plant startup scheduled for November 2016. The plant had a total estimated cost of $24.6 million or $7.84net to the Company, of which approximately $23.9 million had been incurred as of September 30, 2016. The June 30, 2016 reserves report includes projected peak gross proved production volumes of approximately 1,850 barrels of liquids per barrel,day from the NGL plant over the next five years. The methane removed by the plant will be converted to electricity to supply power for the NGL plant and reduce electricity costs for the recycling facility. The NGL plant is also expected to increase the sweep efficiency and recovery of the CO2 flood by removing hydrocarbons for the recycle stream.

Late in fiscal 2016, the operator began a $2.5 million gross ($0.6 million net to Evolution) project to restore production in the southwestern portion of the field. Following the fluid release event in June 2013, CO2 injections in this area ceased in order to reduce reservoir pressure and protect the incident area. The project encompassed converting three shut-in wells to water injector wells in order to expand the water curtain barrier to reduce CO2 migration and the installation of three electrical submersible pumps ("ESP") in other shut-in wells in order to increase withdrawal rates and help maintain the targeted reservoir pressure. These ESP production wells created a modified waterflood, which are reported as other incomebegan producing in September 2016.

Liquidity and not included in revenues.Capital Resources

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Delhi lifting costs were $13.44 per barrel, an 18% decrease from $16.37 in the prior quarter, due to lower field costs, lower price of CO2 and reduced volumes of CO2 purchased for the field.

We successfully completed the separation and transfer of our GARP® artificial lift technology operations, resulting in a one-time personnel restructuring charge of $0.7 million and a non-cash impairment charge of $0.6 million. The recurring annual overhead cost savings to the Company are estimated to be approximately $1.0 million per year.
 
NetWe had $28.2 million and $34.1 million in cash and cash equivalents at September 30, 2016 and June 30, 2016, respectively. In addition, we had $10.0 million of availability under our senior secured reserve-based credit facility.

On April 11, 2016, the Company entered into a new three-year, senior secured reserve-based credit facility ("Facility") with MidFirst Bank. The Facility provides a senior secured revolving credit facility with an initial borrowing base of $10 million (the “Borrowing Base”) and a maximum borrowing amount of $50 million. The Facility matures on April 11, 2019, and is secured by substantially all of the Company’s assets.
The Borrowing Base is subject to periodic redeterminations and further adjustments from time to time. The Borrowing Base will be redetermined semi-annually on May 15 and November 15 of each year. The Borrowing Base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and changes to certain hedging positions. With the recent volatility in commodity prices, our borrowing base and related commitments under the Facility could be reduced in the future. The Facility bears interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined, plus 1.0%. 

The Facility contains certain covenants, which, among other things, require the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of not less than $40 million, each as defined in the Facility. The Facility also contains other affirmative and negative covenants and events of default. As of September 30, 2016, the Company was in compliance with all covenants contained in the Facility, and no amounts were outstanding under the Facility.

During the three months ended September 30, 2016, we funded our operations with cash generated from operations and cash on hand. At September 30, 2016, our working capital was $19.6 million, compared to working capital of $28.6 million at June 30, 2016.  The $9.0 million decrease in working capital is primarily attributable to the $7.9 million accrual of preferred stock called for redemption.

Capital Budget - Delhi Field

During the three months ended September 30, 2016, we incurred $2.8 million of capital expenditures, which includes $2.4 million for the NGL plant and $0.4 million for other field capital.
For fiscal 2017, we expect approximately $3.0 to $4.0 million in final spending for the NGL plant. As of September 30, 2016, we had incurred approximately $23.9 million of cumulative capital costs for the NGL plant out of an original commitment of $24.6 million. The remaining committed capital costs are expected to be incurred in the fourth quarter of calendar 2016 and the completed cost of the project is expected to be largely within the original budget. In late September and October, we approved eleven small capital workover projects for continuing conformance operations in the Delhi field, totaling approximately $3.8 million ($0.9 million net to us). There are three workover rigs operating in the field and we expect all of these operations to be completed by the end of the year. These new projects result from the demonstrated benefits from previous conformance efforts and the significant returns that have been realized from relatively modest capital investments in the field. These conformance projects add production and cash flow in a very short time frame after investment. In addition, there will likely be other spending on unbudgeted capital projects for capital workovers or production enhancement during the current fiscal year, which we do not expect to have a material effect on our financial position.
 Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Our preference is to remain debt free under our current operating plans, but we have access to a senior secured credit facility for oil and gas development if required. In addition, we have an effective shelf registration statement with Securities and Exchange Commission. We may choose to evaluate new growth opportunities through acquisitions or other transactions. In that event, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. In June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility with the goal to achieve a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. The Company uses both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. We have no derivative commitments beyond September 30, 2016 at this time. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow,

profitability, access to capital and future rate of growth are significantly impacted by the prices we receive for our production. Liquidity could also be affected by any litigation outcome, positive or negative.
Payment of free cash flow in excess of our operating and capital requirements through cash dividends and potential repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate.
The Board of Directors and management instituted a cash dividend on our common stock in December 2013 at an initial quarterly rate of $0.10 per common share. As a result of the decline in oil prices which began in the fall of 2014, combined with the anticipated cost of building and installing the Delhi NGL plant during calendar years 2015 and 2016, the Board of Directors concluded it was prudent to adjust the quarterly dividend rate from $0.10 per share to $0.05 per share, effective beginning in the quarter ended March 31, 2015. With the NGL plant construction commitment largely complete, the Company announced in November 2016 an increase in the common stock cash dividend to $0.065 per share effective with the dividend payment in the following month.
In May 2015, we established a stock repurchase plan to allow us acquire up to $5.0 million of our common stock over time, of which we have approximately $3.4 million remaining. The actual timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. In general, our share repurchase program is limited to discretionary funds and is of lesser importance than our primary objectives related to our development capital spending at Delhi and our common stock dividend program. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time.
On September 30, 2016 the Board of Directors approved the redemption of all of the Company's 8.5% Series A Cumulative Preferred Stock to occur on November 14, 2016. Though reduced by this transaction, working capital remains strong at $13.7a healthy level and the Company also has access to capital at a significantly lower cost from its existing undrawn credit facility.
Cash Flows from Operating Activities
For the three months ended September 30, 2016, cash flows provided by operating activities were $1.5 million, reflecting $1.8 million of cash provided by net income, $2.3 million provided by adjustments reconciling net income to cash provided by operating activities, and Evolution declared its tenth consecutive quarterly$2.7 million used by changes in operating assets and liabilities.
For the three months ended September 30, 2015, cash flows provided by operating activities were $2.2 million, which included $0.4 million used by other working capital items.  Of the $2.7 million provided before other working capital changes, approximately $3.1 million was due to net income that was partly offset by $0.4 million of non-cash items.

Cash Flows from Investing Activities

Investing activities for the three months ended September 30, 2016 used $5.2 million of cash, consisting primarily of capital expenditures of approximately $4.8 million for the Delhi field and $0.3 million for derivative settlements paid.
Investing activities for the three months ended September 30, 2015 used $6.0 million of cash, consisting primarily of capital expenditures of approximately $6.6 million for Delhi field offset by $0.6 million of derivative settlements received.

Cash Flows from Financing Activities
For the three months ended September 30, 2016, financing activities used $2.2 million of cash, consisting of $1.8 million of dividend payments to common and preferred shareholders and $0.3 million of common share repurchases related to shares surrendered for tax withholding.

For the three months ended September 30, 2015, financing activities were cash neutral as $1.8 million of common and preferred shares' cash dividend on common shares.

We remain debt free.payments and $1.2 million of treasury acquisitions, primarily attributable to the Company's share buyback program, were offset by $3.0 million of cash provided by tax benefits related to stock-based compensation. These tax benefits include the $1.5 million impact of the cash refund received from the State of Louisiana for previously filed carryback returns.

Full Cost Pool Ceiling Test and Proved Undeveloped Reserves
For the quarter ended December 31, 2015,September 30, 2016, our capitalized costs of oil and gas properties were well below the full cost valuation ceiling and weceiling. We do not currently expect that a write-down of capitalized oil and gas property costs will be required in the remaining quarters of fiscal 2016.2017. However, lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited toto: the estimated future net cash flows from proved oil and gas reserves, discounted at 10%,; plus the cost of any properties not being amortized; plus the lower of cost or fair value of unproved properties as adjusted for relatedincluded in costs being amortized; less the income tax effectseffect related to the differences between the book and tax basis of the properties (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the average price received for our petroleum products during the twelve month period ending with the balance sheet date. If commodity prices remain at the current quarter’s lower levels, the average prices used in future ceiling test calculations will decline. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future.
Our proved undeveloped reserves in the Delhi field consist primarily of the NGL plant and development of the remaining eastern part of the field. TheRemaining estimated future capital expenditures amount to $8.12 per BOE for the Phase V expansion of the CO2 flood in the undeveloped eastern part of the field included in proved undeveloped reserves. Given the geology of the Delhi field, no remaining estimated capital expenditures are $9.34 per BOErequired to develop our probable or possible reserves as these reserves reflect incremental quantities associated with a greater percentage recovery of hydrocarbons in place than the recovery quantities assumed for proved undeveloped reserves. The NGL plant is currently under constructionessentially completed and we expect the first full month of production in December 2016. The expanded development of the eastern part of the Delhi field was commenced upon the reversion of our working interest in November 2014. Shortly thereafter, the operator reduced its capital budget and temporarily postponed development of the eastern part of the Delhi field. Resumption of this development project is dependent, at least in part, on the operator's allocation of available capital to projects within their portfolio. Both we and the operator believe that it is prudent to complete the NGL plant before continuing with future development of the field as the plant is projected to improve subsequent field economics. At this time, despite lower commodity price levels, we continue to believe that these projects are economically viable and it is probable they will be executed within the next fiveseveral years. We base our analysis on the current lifting costs in the field and the relatively low future development costs per BOE. Therefore, we believe these reserves remain properly classified as proved undeveloped reserves under SEC guidelines.
Projects
Additional property and project information is included under Item 1. Business, Item 2. Properties, Notes to the Financial Statements and Exhibit 99.4 of our Form 10-K for the year ended June 30, 2015.
Delhi Field - Enhanced Oil Recovery Project

Gross production at Delhi in the second quarter of fiscal 2016 averaged 6,810 BOPD, an increase of 16% from the year-ago quarter, and a 6% increase from the prior quarter. Net production averaged 1,801 BOPD, a 52% increase from the year-ago quarter, and a 6% increase from prior quarter. The large year-over-year increase in net production volumes was the result of an increase in both gross production volumes and the reversion of our 23.9% working interest in the Delhi field on November 1, 2014, which means we did not realize a full quarter of production associated with our reversionary working interest in the second quarter of fiscal 2015.

Field operating expenses were $13.44 per barrel, an 18% reduction from levels in the prior quarter, resulting primarily from lower purchased CO2 costs. In the quarter ending December 31, 2015, our net share of the lease operating expenses was approximately $2.2 million, of which $1.0 million is related to CO2 purchases and transportation expenses. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per thousand cubic feet (“Mcf”) plus sales taxes of

18


8% plus transportation costs of $0.20 per Mcf. CO2 costs decreased 27% from the prior quarter as result of both lower oil prices and lower purchased CO2 volumes in the quarter. Purchased CO2 gross volumes in the current quarter averaged 73,312 Mcf per day, a decline of 18% from 89,705 Mcf per day in the prior quarter. Despite lower purchased CO2 volumes, the overall oil production has been increasing over the past few quarters. On a total BOE basis, average CO2 costs were down 31% from $8.89 per BOE in the prior quarter to $6.14 per BOE, as the result of lower CO2 volumes purchased and lower realized oil prices. Our purchased CO2 costs are substantially correlated with realized oil prices.

Based on recent discussions with the operator, the fabrication, construction and installation of the NGL plant are continuing and completion is anticipated in the fourth quarter of calendar 2016. The plant has a total estimated cost of $24.6 million net to the Company, of which approximately $9.4 million had been incurred as of December 31, 2015. The pace of spending on the NGL plant has been slower than originally projected by the operator, as they have been focused on making the best decisions on design and selection of contractors and have attempted to reduce costs in this current low pricing environment for materials and services required for the plant. Consequently, we believe that our ultimate net costs for the project may be below our initial commitment, however this will not be known until the project is completed. The June 30, 2015 reserves report includes projected peak gross proved production volumes of approximately 1,850 barrels of liquids per day from the NGL plant over the next five years, and peak gross probable volumes of 1,140 barrels of liquids per day later next decade. The methane removed by the plant will be utilized to supply power for the NGL plant and reduce electricity costs for the recycling facility. The NGL plant is also expected to increase the sweep efficiency and recovery of the CO2 flood, therefore the reserves report reflects incremental gross crude oil production volumes of approximately 500 BOPD once the plant is operational.     
GARP® - Artificial Lift Technology

Based on a strategic review of our GARP® artificial lift technology operations, we completed the separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the new entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future success of the technology, while eliminating our overhead and operating commitments associated with GARP®. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.

This transaction resulted in a one-time personnel restructuring charge of $0.7 million, along with non-cash asset impairments of approximately $0.6 million. The separation will reduce our overhead costs by an estimated $1.0 million per year and remove our obligation to fund the future capital and operating needs of this operation.

Liquidity and Capital Resources
We had $16.3 million million and $20.1 million in cash and cash equivalents at December 31, 2015 and June 30, 2015, respectively. In addition, we have $5.0 million of availability under our unsecured revolving credit facility.

During the six months ended December 31, 2015, we funded our operations with cash generated from operations and cash on hand. At December 31, 2015, our working capital was $13.7 million, compared to working capital of $14.4 million at June 30, 2015.  The $0.7 million decrease in working capital consists primarily of a $3.8 million reduction in cash, partly offset by a $3.3 million decrease in accounts payable and other changes in working capital.
Cash Flows from Operating Activities
For the six months ended December 31, 2015, cash flows provided by operating activities were $4.5 million, reflecting $3.9 million of cash provided by net income, $0.3 million used by adjustments reconciling net income to cash provided by operating activities, and $0.9 million provided by changes operating assets and liabilities.
For the six months ended December 31, 2014, cash flows provided by operating activities were $4.6 million, which included a small impact from changes in other working capital items.  Of the $4.6 million provided, approximately $2.4 million was due to net income, and approximately $2.2 million was attributable to non-cash expenses.

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Cash Flows from Investing Activities
Investing activities for the six months ended December 31, 2015 used $7.2 million of cash, consisting primarily of capital expenditures of approximately $8.7 million for the Delhi field, slightly offset by $1.6 million of derivative settlements received.

Investing activities for the six months ended December 31, 2014 used less than $0.1 million of cash, consisting of capital expenditures of approximately $0.3 million artificial lift technology operations and $0.1 million for GARP® patent costs, offset by $0.4 million of proceeds received from the sale of properties in the Mississippi Lime project.

Cash Flows from Financing Activities
For the six months ended December 31, 2015, financing activities used $1.1 million of cash, consisting of $3.6 million of dividend payments to common and preferred shareholders and $1.4 million of treasury stock acquisitions, primarily attributable to the Company's share buyback program, which were partially offset by $3.9 million of tax benefits related to stock-based compensation. These tax benefits include a $1.5 million cash refund received from the State of Louisiana for previously filed carryback returns.

During the six months ended December 31, 2014, we used $6.1 million in cash for financing activities, consisting principally of $6.9 million of dividend payments to common and preferred shareholders, offset partially by $0.9 million of cash provided by tax benefits related to stock-based compensation.

Capital Budget
Delhi Field
During the six months ended December 31, 2015, we incurred $6.3 million of capital expenditures, which includes $4.4 million for the NGL recovery plant, $0.8 million for enhancing well bore integrity, $1.0 million for general maintenance capital within the field and $0.1 million of leasehold costs.
As of December 31, 2015, we had incurred approximately $9.4 million of cumulative capital costs for the NGL recovery plant out of an original commitment of $24.6 million. The remaining committed capital costs of approximately $15.2 million are expected to be incurred over the remainder of calendar 2016. In addition, there will likely be other spending on unbudgeted capital projects for maintenance or production enhancement during the current fiscal year, which we do not expect to have a material effect on our financial position.
GARP® - Artificial Lift Technology
Based on a strategic review of our GARP® artificial lift technology operations, we completed the separation and transfer of these operations to a new entity controlled by the inventor of the technology and certain former employees of the Company, effective December 31, 2015. We invested $108,750 in common and preferred stock and retained a minority interest in the new entity, together with a 5% royalty on all future gross revenues derived from the technology. We have the option to convert our preferred stock investment into a larger, non-controlling equity stake in the new entity. Consequently, we have retained substantial upside for our shareholders from the potential future success of the technology, while eliminating our overhead and operating commitments associated with GARP®. We have also retained the right to use the technology in our current wells and any future wells we develop or acquire.
Liquidity Outlook
Funding for our anticipated capital expenditures during this fiscal year is expected to be met from cash flows from operations and current working capital. We expect to remain debt free under our current operating plans, but we have access to a $5.0 million unsecured revolving line of credit. This facility is intended primarily to provide a standby source of liquidity to meet future capital expenditures at Delhi or other future capital needs. We are currently seeking to renew the unsecured revolving line of credit or a similar source of bank financing.
Our liquidity is highly dependent on the realized prices we receive for the oil, natural gas and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. In June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for approximately two-thirds of its forecasted production from July 1, 2015 to December 31, 2015 to achieve a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. Costless collars used by the Company to manage risk are designed to establish floor and ceiling prices on a part of anticipated future oil production. In October 2015, to reduce exposure

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to oil price volatility for approximately two-thirds of forecasted production from January 1, 2016 to March 31, 2016, we acquired a series of swaps, which provide a fixed price consisting of identical floor and ceiling prices. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth are significantly impacted by the prices we receive for our production. Liquidity could also be affected by any litigation outcome, positive or negative.
The Board of Directors and management instituted a cash dividend on our common stock in December 2013 at an initial quarterly rate of $0.10 per common share. However, as a result of the decline in oil prices which began in the fall of 2014, combined with the anticipated $24.6 million cost of building and installing the Delhi NGL gas plant during calendar years 2015 and 2016, the Board of Directors concluded it was prudent to adjust the quarterly dividend rate from $0.10 per share to $0.05 per share, effective with the quarter ended March 31, 2015. The reduction in the dividend rate allows the Company to conserve cash for additional financial flexibility while continuing to reward shareholders with a yield. In addition, in May 2015, we established a stock repurchase plan to allow us acquire up to $5.0 million of our common stock over time. The actual timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time. Payment of free cash flow in excess of our operating and capital requirements through cash dividends and repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase our dividends over time as appropriate.

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Results of Operations
Three Months Ended December 31,September 30, 2016 and 2015 and 2014
The following table sets forth certain financial information with respect to our oil and natural gas operations:
Three Months Ended December 31,    Three Months Ended September 30, 
  
2015 2014 Variance Variance %2016 2015 Variance Variance %
Delhi field (see note below):       
Crude oil revenues$6,558,215
 $7,644,831
 $(1,086,616) (14.2)%
Crude oil volumes (Bbl)165,654
 109,200
 56,454
 51.7 %
Average price per Bbl$39.59
 $70.01
 $(30.42) (43.5)%
       
Delhi field production costs$2,226,141
 $2,817,866
 $(591,725) (21.0)%
Delhi field production costs per BOE$13.44
 $25.80
 $(12.36) (47.9)%
       
Artificial lift technology:       
Oil and gas production:       
Crude oil revenues$7,589
 $42,039
 $(34,450) (81.9)%$7,593,855
 $7,325,813
 $268,042
 3.7 %
NGL revenues685
 11,028
 (10,343) (93.8)%89
 1,050
 (961) (91.5)%
Natural gas revenues317
 7,365
 (7,048) (95.7)%(4) 704
 (708) n.m.
Service revenues56,121
 2,804
 53,317
 1,901.5 %
Total revenues$64,712
 $63,236
 $1,476
 2.3 %$7,593,940
 $7,327,567
 $266,373
 3.6 %
              
Crude oil volumes (Bbl)193
 563
 (370) (65.7)%178,002
 156,916
 21,086
 13.4 %
NGL volumes (Bbl)42
 411
 (369) (89.8)%4
 82
 (78) (95.1)%
Natural gas volumes (Mcf)182
 2,413
 (2,231) (92.5)%16
 307
 (291) n.m.
Equivalent volumes (BOE)265
 1,376
 (1,111) (80.7)%178,009
 157,049
 20,960
 13.3 %
              
Equivalent volumes per day (BOE/D)1,935
 1,745
 190
 10.9 %
       
Crude oil price per Bbl$39.32
 $74.67
 $(35.35) (47.3)%$42.66
 $46.69
 $(4.03) (8.6)%
NGL price per Bbl16.31
 26.83
 (10.52) (39.2)%22.25
 12.80
 9.45
 73.8 %
Natural gas price per Mcf$1.74
 3.05
 (1.31) (43.0)%(0.25) 2.29
 (2.54) n.m.
Equivalent price per BOE$32.42
 $43.92
 $(11.50) (26.2)%$42.66
 $46.66
 $(4.00) (8.6)%
              
Artificial lift production costs (a)$53,731
 $191,553
 $(137,822) (71.9)%
Artificial lift production costs per BOE$202.76
 $139.21
 $63.55
 45.7 %
CO2 costs
$1,078,133
 $1,388,926
 $(310,793) (22.4)%
All other lease operating expense1,266,508
 1,219,653
 46,855
 3.8 %
Production costs$2,344,641
 $2,608,579
 $(263,938) (10.1)%
Production costs per BOE$13.17
 $16.61
 $(3.44) (20.7)%
              
Other properties:       
Production costs$
 $9,390
 $(9,390) (100.0)%
CO2 volumes mcf per day, gross
73,747
 89,705
 (15,958) (17.8)%
              
Combined:       
Oil and gas DD&A (b)$1,254,350
 $701,543
 $552,807
 78.8 %
Oil and gas DD&A (a)$1,265,637
 $1,188,872
 $76,765
 6.5 %
Oil and gas DD&A per BOE$7.56
 $6.34
 $1.22
 19.2 %$7.11
 $7.57
 $(0.46) (6.1)%
       
Artificial lift technology services:       
Services revenues$
 $51,839
 $(51,839) n.m.
Cost of service
 9,868
 (9,868) n.m.
Depreciation and amortization expense$
 $25,384
 $(25,384) n.m.
       

Note: Resultsn.m. Not meaningful.

(a) Excludes depreciation and amortization expense for artificial lift technology services and $7,802 and $4,017 of other depreciation and amortization expense for the three months ended December 31, 2014 do not include revenues, production costsSeptember 30, 2016 and net volumes from our working interest in the Delhi field prior to reversion on November 1, 2014 and therefore may not be comparable to subsequent periods.

(a) Includes workover costs of approximately $0 and $134,000, for the three months ended December 31, 2015, and 2014, respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $217,221 and $216,214, for the three months ended December 31, 2015 and 2014, respectively.

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Net Income Available to Common Stockholders. For the three months ended December 31, 2015,September 30, 2016, we generated net income to common shareholders of $0.7$0.6 million, or $0.02 per diluted share, on total revenues of $6.6$7.6 million. This compares to net income of $1.1$2.9 million, or $0.03$0.09 per diluted share, on total revenues of $7.7$7.4 million for the year-ago quarter.period.  The $0.4$2.4 million earnings decrease resulted from $2.0 million decrease in derivative gains, $1.1 million from a year-ago insurance recovery, and a $1.1 million revenue decline and $1.5increase in allocated net income to holders of called preferred shares, partially offset by $0.2 million of higher operating expenses (which included a $1.3 million non-recurring restructuring charge), partially offset by $1.7revenue, $0.7 million of derivative gainslower operating costs and $0.5$0.9 million of lower income taxes.
Delhi FieldOil and Gas Production.. Revenues decreased 14%increased 3% to $6.6$7.6 million  primarily as a result of a 43% decline in realized crude oil prices from $70.01 per barrel to $39.59 per barrel. This was partially offset by a 52%13% increase in production volumes from the year-ago quarter, which did not reflectperiod, partially offset byfull quarter of9% decline in realized prices from $46.66 per equivalent barrel to $42.66 per barrel in the current period. Delhi oil production as reversionand revenues comprise virtually all of our working interest did not occur until November 1, 2014. Grossrevenues. Delhi gross production of 6,8107,371 BOPD was 16%14.8% higher compared to the year-ago quarterperiod as a result of production enhancement and conformance operations in the field.
Production Costs. Production costs for the three months ended September 30, 2016 were $2.3 million, a $0.3 million decrease from the year-ago quarter primarily attributable to the Delhi field. Delhi production costs for the current quarterperiod were $2.2$2.3 million of which $1.0$1.1 million was for CO2 costs, compared to $2.8$2.6 million, of which $1.7$1.4 million was for CO2 costs, in the year-ago quarter. Under our contract with the operator, purchased CO2 is priced at 1% of the oil priceperiod. Average gross injection volumes decreased from 89,705 Mcf per day in the fieldyear-ago period to 73,747 Mcf per Mcf plus sales taxes at 8% plus $0.20 per Mcf transportation costs.day for the current quarter. For the current quarter, production costs were $13.44$13.17 per BOE on total production volumes. Production costs were $18.67$18.09 per BOE calculated solely on our Delhi working interest volumes, which includes $8.53$8.35 per working interest BOE for COcosts. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.
Artificial Lift Technology. Revenues of $0.1 million were virtually flat compared to the year-ago quarter. An increase in service revenue was offset by decreased revenue from operated wells. Production volumes declined 81% to 265 BOE and the price per BOE decreased 26% to $32.42. Production costs decreased by approximately $0.1 million, as workover expenses on our operated wells were lower than the year-ago quarter.
General and Administrative Expenses (“G&A”). G&A expenses increased $0.5decreased $0.4 million, or 28%27%, to $2.1$1.2 million for the three months ended December 31, 2015September 30, 2016 from the year-ago quarter, principally asperiod primarily due to a result of $0.6$0.3 million of higherdecrease in litigation costs partially offset by $0.1 million ofand a lower accruals for short-term incentive compensation. Total litigation costs for the quarter were approximately $0.7 million.
Restructuring charge. We recognized a $1.3 million restructuring charge in the current quarter related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of the charge resulted from impairments of assets used in those operationssalary and $0.7 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.benefit expenses.
Other Income and Expenses. The Company realized gains of $1.3 million from derivatives that settled duringFor the quarter and $0.4three months ended September 30, 2016, aggregate other items decreased $3.0 million from the net changeyear-ago quarter due to a $2.0 million decrease in unsettled derivative positions.gains and a year-ago $1.1 million gain from an insurance recovery at the Delhi field.
Depreciation, Depletion & Amortization Expense (“DD&A”).  DD&A increased $0.6$0.1 million, or 60%5%, to $1.5 million for the current quarter compared to $0.9 million for the year-ago quarter, primarily as a result of $0.6 million of higher amortization of the full cost pool. Production volumes increased 50% to 165,919 BOE and the amortization rate increased 19% to $7.56 per BOE. Compared to the year-ago quarter, the increased amortization rate was impacted by increased future development costs in the June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were previously expected to be borne by the third party operator of the plant and decreases in reserves from the loss of the Philip DL #1 late in fiscal 2015 and from the decision to use produced methane at Delhi internally to generate power thereby lowering field operating costs rather than selling the methane to third party customers.

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 Six Months Ended December 31, 
  
 2015 2014 Variance Variance %
Delhi field (see note below):       
Crude oil revenues$13,854,601
 $11,513,433
 $2,341,168
 20.3 %
Crude oil volumes (Bbl)321,890
 148,294
 173,596
 117.1 %
Average price per Bbl$43.04
 $77.64
 $(34.60) (44.6)%
        
  Delhi field production costs$4,784,028
 $2,817,866
 $1,966,162
 69.8 %
  Delhi field production costs per BOE$14.86
 $19.00
 $(4.14) (21.8)%
        
Artificial lift technology:       
  Crude oil revenues$37,016
 $117,019
 $(80,003) (68.4)%
  NGL revenues1,735
 33,255
 (31,520) (94.8)%
  Natural gas revenues1,021
 22,917
 (21,896) (95.5)%
  Service revenues107,960
 5,901
 102,059
 1,729.5 %
  Total revenues$147,732
 $179,092
 $(31,360) (17.5)%
        
  Crude oil volumes (Bbl)873
 1,335
 (462) (34.6)%
  NGL volumes (Bbl)124
 1,155
 (1,031) (89.3)%
  Natural gas volumes (Mcf)489
 6,852
 (6,363) (92.9)%
  Equivalent volumes (BOE)1,078
 3,632
 (2,554) (70.3)%
        
  Crude oil price per Bbl$42.40
 $87.65
 $(45.25) (51.6)%
  NGL price per Bbl13.99
 28.79
 (14.80) (51.4)%
  Natural gas price per Mcf2.09
 3.34
 (1.25) (37.4)%
    Equivalent price per BOE$36.89
 $47.68
 $(10.79) (22.6)%
        
  Artificial lift production costs (a)$113,245
 $388,913
 $(275,668) (70.9)%
  Artificial lift production costs per BOE$105.05
 $107.08
 $(2.03) (1.9)%
        
Other properties:       
  Revenues$
 $20,369
 $(20,369) (100.0)%
  Equivalent volumes (BOE)
 285
 (285) (100.0)%
  Equivalent price per BOE$
 $71.47
 $(71.47) (100.0)%
        
  Production costs$1,046
 $97,412
 $(96,366) (98.9)%
  Production costs per BOEn/a
 $341.80
 n/a
 n/a
        
Combined:       
Oil and gas DD&A (b)$2,443,222
 $961,703
 $1,481,519
 154.1 %
Oil and gas DD&A per BOE$7.56
 $6.32
 $1.24
 19.6 %

Note: Results for the six months ended December 31, 2014 do not include revenues, production costs and net volumes from our working interest in the Delhi field prior to reversion on November 1, 2014 and therefore may not be comparable to subsequent periods.

(a) Includes workover costs of approximately $9,901 and $283,000 for the six months ended December 31, 2015 and 2014, respectively.

(b) Excludes depreciation of artificial lift technology equipment, office equipment, furniture and fixtures, and other assets of $246,622 and $325,404 for the six months ended December 31, 2015 and 2014, respectively.

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Net Income Available to Common Stockholders.  For the six months ended December 31, 2015, we generated net income to common shareholders of $3.6 million, or $0.11 per diluted share, on total revenues of $14.0 million. This compares to net income of $2.0 million, or $0.06 per diluted share, on total revenues of $11.7 million for the year-ago period.  The $1.5 million earnings increase resulted from $2.3 million of higher revenue, $3.5 million of derivative gains, and $1.1 million from an insurance recovery, partially offset by $4.9 million of higher operating expenses (which include a $1.3 million non-recurring restructuring charge) and $0.5 million of higher income taxes.
Delhi Field. Revenues increased 20% to $13.9 million as a result of a 117% increase in production volumes from the year-ago period, partially offset by a 45% decline in realized crude oil prices from $77.64 per barrel to $43.04 per barrel. The year-ago period did not include a full six months of net production, revenues or production costs as reversion of our working interest did not occur until November 1, 2014. Gross production of 6,616 BOPD was 14% higher compared to the year-ago period as a result of production enhancement and conformance operations in the field. Production costs for the current period were $4.8 million, of which $2.4 million was for CO2 costs, compared to $2.8 million, of which $1.7 million was for CO2 costs, in the year-ago period. Under our contract with the operator, purchased CO2 is priced at 1% of the oil price in the field per Mcf plus sales tax at 8% plus $0.20 per Mcf transportation costs. For the six months ended December 31, 2015, production costs were $14.86 per BOE on total production volumes. Production costs were $20.64 per BOE calculated solely on our working interest volumes, which includes $10.38 per working interest BOE for CO2 costs. These latter production costs per BOE exclude production volumes from our royalty interests in the Delhi field, which bear no production costs, and are therefore higher than the rates per BOE on our total production volumes.
Artificial Lift Technology. Revenues declined 18% to $0.1 million as a result of significantly lower revenue on our operated wells, offset by $0.1 million of higher GARP® service revenue. Production volumes decreased 70% to 1,078 BOE and the price per BOE decreased from $47.68 in the prior period to $36.89. Production costs declined by $0.3 million to $0.1 million, compared to $0.4 million in the prior period, primarily as a result of lower workover expenses on our operated wells.
General and Administrative Expenses (“G&A”).  G&A expenses increased $0.6 million, or 20% to $3.7 million for the six months ended December 31, 2015 from the year-ago period, principally as a result of an $0.8 million increase in litigation costs and a $0.1 million increase in salaries and payroll benefits, partially offset by $0.3 million of lower accruals for short-term incentive compensation. Total litigation costs for the period were approximately $1.0 million.
Restructuring charge. Effective December 31, 2015, we recognized a $1.3 million restructuring charge related to the separation of our GARP® artificial lift technology operations. Approximately $0.6 million of the charge consists of the impairment of assets used in that operation and $0.7 million was associated with accrued personnel termination costs to be paid from January 2016 through June 2017. Such termination costs also include approximately $0.1 million of non-cash stock compensation expense from the accelerated vesting of restricted stock. As a result of the restructuring, future annual overhead cost savings are estimated to be approximately $1.0 million per year.
Other Income and Expenses. During the six months ended December 31, 2015, the Company realized gains of $2.2 million from derivatives that settled derivatives, $1.4 million for unsettled derivatives and $1.1 million from an insurance recovery at the Delhi field.
Depletion & Amortization Expense (“DD&A”).  DD&A increased $1.4 million, or 109% to $2.7 million for the current period compared to $1.3$1.2 million for the year-ago period as a result of $1.5$0.1 million of higher amortization of the full cost pool, partially offset by lower depreciation on artificial lift technology equipment, miscellaneous fixed assets and other assets. From the year-ago period production volumes increased 112% to 322,968 BOE and the amortization rate increased 20% to $7.56 per BOE. Compared to the year-ago period, the increasedquarter, the increase in full cost pool amortization was due to a 13% production increase to 178,009 BOE, partially offset by a 6% lower amortization rate was impacted by increasedof $7.11 per BOE. The rate decrease is primarily due to lower future development costs incompared to the year-ago quarter as certain proved undeveloped reserves, particularly Phase VI area, were found to be uneconomical at June 30, 2015 reserves report for the Delhi NGL plant, a portion of which costs were previously expected to be borne by the third party operator of the plant and decreases in reserves from the loss of the Philip DL #1 late in fiscal 2015 and from the decision to use produced methane at Delhi internally to generate power thereby lowering field operating costs rather than selling the methane to third party customers.2016.
Other Economic Factors
Inflation. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services greatly impact our production costslease operating expenses and our capital expenditures. During fiscal 2014, we saw modest increases in certain oil field services2016 and materials compared to the prior fiscal year.  During fiscal 20152017 to date, we have not seen material changessome declines in operating and capital costs as a result of lower demand and excess supply of goods and services in wells that we operate, but operating costs in our third

25


party operated Delhi field have declined, and we believe such declines are attributable to improved operating efficiencies and generally lower third-party contractor and vendor expenses.the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties.  General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If demandthe supply of crude oil and natural gas continues to decrease with a great oversupplyexceed demand in the future, it may continue to put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward.
Seasonality.  Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products.  Although we do not generally modify our production for changes in market demand, we do experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes, that may substantially affect oil and natural gas production and imports.

Off Balance Sheet Arrangements
 
The Company has no off-balance sheet arrangements to report during the quarter ending December 31, 2015.ended September 30, 2016.
ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Information about market risks for the three months ended December 31, 2015,September 30, 2016, did not change materially from the disclosures in Item 7A of our Annual Report on Form 10-K for the year ended June 30, 2015.2016.
Commodity Price Risk
Our most significant market risk is the pricing for crude oil, natural gas and NGLs. We expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, our revenues and cash flow would significantly decline. In addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital, as, if and when needed. We may use derivative instruments to manage our exposure to commodity price risk from time to time based on our assessment of such risk.
Interest Rate Risk 
We currently have only a small exposure to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents.  Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate changes.

ITEM 4. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to this Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow for timely decisions regarding required disclosure.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision and with the participation of the Company’s management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(c) and 15d-15(e)) as of the end of the quarter covered by this report.  In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives.  Based on the foregoing, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2015September 30, 2016 our disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, during the quarter ended December 31, 2015September 30, 2016 we have determined there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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Table of Contents



PART II - OTHER INFORMATION
 
ITEM 1. LEGAL PROCEEDINGS
We are involved in certain legal proceedings that are described in Part I. Item 3. “Legal Proceedings” and Note 1718Commitments and Contingencies under Part II. Item 8. “Financial Statements” in our 20152016 Annual Report. Material developments in the status of those proceedings during the quarter ended December 31, 2015September 30, 2016 are described in Part I. Item 1. "Financial Information" under Note 1615Commitments and Contingencies in this Quarterly Report and incorporated herein by reference. We believe that the ultimate liability, if any, with respect to these claims and legal actions will not have a material effect on our financial position or on our results of operations.


ITEM 1A. RISK FACTORS
Our Annual Report on Form 10-K for the year ended June 30, 20152016 includes a detailed discussiondescription of our risk factors. In addition to those, we add the following risk factor below:
We are materially dependent upon our operator with respectThere have been no material changes to the successful operation of our principal asset, which consists of our interests the Delhi Field. A materially negative changerisk factors previously disclosed in our operator’s financial condition could negatively affect operations inAnnual Report on Form 10-K for the Delhi Field, and consequently our income from the field as well as the value of our interests in the Delhi Field.year ended June 30, 2016.
Our royalty, mineral and working interests in the Delhi Field, located in Northeast Louisiana, are currently our most significant asset. Over 99% of our revenues come from these interests and thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations and financial results. We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”). Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2- Enhanced Oil Recovery (“EOR”) project in the Delhi Field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be invested to fully develop the EOR project, further increase production and maximize the value of this asset. The operator's failure to manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2- EOR project to fall short of our expectations in volume and/or timing. Such occurrences could have a material adverse effect on us, and our results of operations and financial condition. 
Our economic success is thus materially dependent upon the Delhi Field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental, strategic and logistical risks, among other things. 
During the fall of 2014, the operator initiated work on expansion of the CO2 flood in the undeveloped eastern part of the field. These operations were suspended by the end of 2014 when the operator made significant cuts in its capital budget as a result of declining oil prices. While we believe that expansion remains economic at current commodity prices, resumption of this work could be electively delayed due to prevailing oil prices and the operator’s allocation of capital for such projects, negatively impacting us.
We are aware that the DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current level of indebtedness and the related financial covenants. They have stated, for example, that their level of indebtedness could have important consequences, including, among others, requiring dedication of a substantial portion of DNR’s cash flow from operations to servicing their indebtedness. They noted that their ability to meet their obligations under their debt instruments will depend in part upon prevailing economic conditions and commodity prices. DNR also noted that it had deferred development spending for certain projects.
Given the current stress in the global commodity markets and oil & gas in particular, our operator could be materially negatively impacted, which could in turn negatively affect the operator’s ability to operate the Delhi Field as well as it’s financial commitment to the EOR project in the field and thus our interests in the Delhi Field could be materially negatively impacted.

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Table of Contents

ITEM 2. UNREGISTERED SALE OF EQUITY SECURITIES AND USE OF PROCEEDS
During the quarter ended December 31, 2015,September 30, 2016, the Company did not sell any equity securities that were not registered under the Securities Act.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2015,September 30, 2016, the Company received shares of common stock from employees of the Company to pay their share of payroll taxes arising from vestings of restricted stock and/or exercises of stock options. The acquisition cost per share reflected the weighted-average market price of the Company’s shares of capital stock at the dates of exercise or restricted stock vesting. In addition, duringDuring the quarter ended December 31, 2015,September 30, 2016, the Company repurchased shares ofdid not purchase any common stock in the open market under the previously announced share repurchase program. The table below summarizes information about the Company's purchases of its common stock during the quarter ended December 31, 2015.September 30, 2016.
Period 
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
Month of October 2015 none Not applicable Not applicable Not applicable
Month of November 2015 18,600 $6.37 Not applicable $3.4 million
Month of December 2015 10,928 $5.53 Not applicable $3.4 million
Period 
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
 
(b) Average Price
Paid per Share (or
Units)
 
(c) Total Number of Shares (or Units) Purchased as Part
of Publicly Announced Plans or Programs
 
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
Month of July 2016 None Not applicable Not applicable $3.4 million
Month of August 2016 1,881 $5.58 Not applicable $3.4 million
Month of September 2016 56,266 $5.67 Not applicable $3.4 million

(1)On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Such shares wereare initially recorded as treasury stock, then subsequently canceled.
(2)During current quarter the Company received 2,00158,147 shares of common stock from certain of its employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock. The acquisition cost per share reflected the weighted-average market price of the Company's shares at the dates vested.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
Not applicable.

ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

ITEM 5. OTHER INFORMATION
None.


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ITEM 6. EXHIBITS
A.           Exhibits
10.1First Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective October 18, 2016 (filed herein.)
31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended.
32.1 Certification of Chief Executive Officer pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
101.LAB XBRL Taxonomy Extension Label Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document


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SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
EVOLUTION PETROLEUM CORPORATION
(Registrant)
 
 
  By:/s/ RANDALL D. KEYS
   Randall D. Keys
   President and Chief Executive Officer
   
Date: February 8,November 9, 2016  


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